Drill bits for drilling a borehole within an earth formation are generally well known in the art. Many conventional drill bits are designed to use cutters that include blades having polycrystalline diamond compact (PDC) cutter elements affixed thereon, mounted on a rotary bit, with the PDC cutter elements arranged such that each engages an earth formation at a desired angle. Drill bits are normally cleaned and cooled during drilling by flowing drilling fluid, or mud, from one or more nozzles on the face of the drill bit. Drilling fluid is pumped down the drill string, flows across the bit face, removing cuttings while cooling the bit, then flows back to the surface through the annulus between the drill string and the borehole wall.
An exemplary drill bit known in the prior art is shown in FIG. 1. Bit 10 is a fixed cutter bit, sometimes referred to as a drag bit or PDC bit, and is adapted for drilling through formations of rock and other earth formations to form a borehole. Bit 10 generally includes a bit body having a shank 13, and a threaded connection or pin 16 for connecting the bit 10 to a drill string (not shown) which is employed to rotate the bit for drilling the borehole. Bit 10 further includes a central axis 11 and a cutting structure on the face 14 of the drill bit, which is shown having a plurality of PDC cutter elements 40 disposed thereon. Also shown in FIG. 1 is a gage pad 12, the outer surface of which is disposed at the diameter of the bit 10 and establishes the bit's size. For example, a 12″ bit will have the gage pad approximately 6″ from the center of the bit.
FIG. 2 depicts a cross-sectional view of the drill bit of FIG. 1. The bit 10 includes a face region 14 and a gage pad region 12. The face region 14 includes a plurality of blades having cutter elements 40 disposed thereon, overlapping in rotated profile. Rotation of the bit 10 causes the cutter elements 40 to drill the borehole as the bit 10 rotates. Downwardly extending flow passages 21 are shown extending through the body of the bit 10, having nozzles or ports 22 disposed at their lowermost ends. A conventional bit 10 can include six such flow passages 21 and nozzles 22. The flow passages 21 are in fluid communication with a central bore 17. Together, the passages 21 and nozzles 22 serve to distribute drilling fluids around the cutter elements 40 for flushing formation cuttings from the bottom of the borehole and away from the cutting faces of cutter elements 40 when drilling.
While gage pads may be used to provide for a borehole having a predictable and constant diameter, it is advantageous at times, to drill a borehole having one or more oversize, or overgauge, regions. This is especially useful during instances where directional drilling or the drilling of highly deviated wellbores is undertaken, as an overgage hole allows for sharper turns.
Often, to change the gage and/or direction of a borehole, conventional drill bits must be removed from the borehole, reconfigred, and reinserted. Though some drill bits omit use of gage pads and other gage retention mechanisms, or use shortened gage pads combined with dulled or flat cutters to resist wear, these drill bits do not reliably allow for a controlled formation of oversized boreholes and are often limited in their directional drilling capabilities, providing a poor lateral response.
A need exists for a drill bit that has cutting surfaces advantageously oriented to enable one or more regions of a borehole to be controllably provided with regular and oversized diameters.
A further need exists for a drill bit that has cutting surfaces advantageously oriented to enable the drill bit to bore in any selected direction, including lateral directions and back reaming, while downhole, without requiring removal of the bit from the borehole.
The present invention meets these needs.